EP4627180A1

EP4627180A1 - Method for installing a subsea tubing hanger and orientate a subsea tree on a subsea wellhead

Info

Publication number: EP4627180A1
Application number: EP22835874.3A
Authority: EP
Inventors: Neil Walker
Original assignee: TotalEnergies Onetech SAS
Current assignee: TotalEnergies Onetech SAS
Priority date: 2022-11-30
Filing date: 2022-11-30
Publication date: 2025-10-08
Also published as: EP4715163A3; WO2024115936A1; EP4715163A2

Abstract

The invention relates to a system and method to prepare a subsea tree to be installed onto a subsea Tubing Hanger, set in a subsea wellhead. The Tubing Hanger orientation / heading is not controlled by traditional subsea methods (i.e. Tubing Head Spool or BOP Pin) and instead is allowed to land inside the wellhead at random 'free' heading. Following subsea measurement of the Tubing Hanger heading, relative to wellhead, the Subsea Tree Alignment Sleeve is manufactured to suit the specific well measurements. The Alignment Sleeve provides the connection between Tubing Hanger and Tree and is the component which provides the correct tree heading to suit the required subsea field architecture.

Description

METHOD FOR INSTALLING A SUBSEA TUBING HANGER AND ORIENTATE A SUBSEA TREE ON A SUBSEA WELLHEAD

Technical field

The present invention relates to the field of subsea oil or gas production wells and injection wells, and more specifically to a method for installing a tubing hanger and tree on a wellhead of a subsea oil or gas production well or a subsea injection well. The invention also relates to an alignment sleeve, an assembly for installing a tubing hanger and tree on a wellhead of a subsea oil or gas production well or a subsea injection well and a subsea wellhead installation for a subsea oil or gas production well or a subsea injection well.

Technical background

Installing a tubing hanger and tree on a subsea wellhead are steps of well completion that take place once drilling of a well has ended, the steps generally comprising orienting the tubing hanger and subsequently the tree to have the same heading as a production guide base (PGB), the production guide base being a foundation for all well completion orientation components that will be installed on the well at the beginning of the construction of the well during the open water drilling stage and before a blow out preventor (BOP) is installed on the wellhead. The PGB has a controlled heading to suit the subsea field architecture/layout while optimizing the well jumper design and manufacture between well/PGB and subsea manifold. In this way, the well jumper can consequently be designed as simply as possible, for example, with a conventional L-shape design.

The typical steps taken to complete the well are more specifically achieved as follows. The BOP is installed on the wellhead (for example on the wellhead high pressure housing using a sealing connector such as a VXT H4 connector) and aligned to the PGB, the BOP has a wellhead capture funnel with an alignment feature that aligns with a corresponding alignment feature on the PGB to enable alignment when the BOP is mated to the PGB. The BOP gives a method of controlling the well during through BOP drilling, preventing a leak or contamination. Once the steps of drilling the well reservoir are finished, the tubing hanger and production tubing are installed using a landing string. The landing string moves the tubing hanger down towards the wellhead and past an alignment pin belonging to the BOP, the alignment pin being configured to move in and out relative to the BOP bore to make contact with the outer diameter of the landing string helical profile. The landing string then moves back up in a direction towards the surface, the pin interfacing with a helical slot (tubing hanger orientation joint, or THOJ) of the landing string thus causing rotation of the string and orientating the tubing hanger into the desired orientation. The landing string then moves downwards once more so that the tubing hanger can land into the wellhead in a correct (pin controlled) orientation to suit the desired final heading of the (to be installed) vertical tree. Once the Tubing Hanger is installed with a controlled (BOP Pin, BOP Alignment Funnel and THOJ) heading, the BOP is recovered back to the drilling rig. After BOP recovery, the tree can be installed onto the PGB and wellhead, with the correct heading to suit the construction of the well jumper, with ‘rough alignment’ provided by the interface between the tree funnel and PGB and ‘fine alignment’ of the tree provided by the interface to the already installed tubing hanger. This fine alignment shall be prior to coupler (also referred to as connection, port) engagement, by an Alignment Sleeve orientation feature (e.g. key) and mating feature inside the tubing hanger. The tree is lowered and is then roughly guided and orientated by a remotely operated underwater vehicle (ROV). The tubing hanger also comprises a key slot or castellations to facilitate alignment with the tree. Alignment of the tree to tubing hanger facilitates the correct alignment of the tree stabs to the tubing hanger bores. Tree stabs can consist of Production and Annulus Stabs, Hydraulic, Electrical and Optical stabs for operation of downhole functions. These connections (tree stabs) are traditionally straight, rigid, vertical and parallel to the well vertical axis. The jumper is then connected between the tree and manifold or inline tree, the PGB comprising a jumper cradle to facilitate the connection. The jumper connection may have a tolerance ranging from, for example, +/- 1 to 2 degrees. The ROV does a last tolerance check before landing the tree onto the tubing hanger and wellhead. The preparation of such a rig to provide this method of orientation control of the tubing hanger is very time consuming. The rig needs to be surveyed, measured and bespoke equipment needs to be manufactured to suit the individual rig. Such preparation can take as long 12 months, or more. In addition, as each BOP is different, it often needs to be surveyed and modified so as to have a bespoke BOP Pin, THOJ and funnel with the appropriate keys for mating with the PGB, the PGB itself not having a universal interface.

Document WO 2019/079041 A1 relates to systems and methods for landing a tubing hanger in a wellhead and then orienting a tree (or spool, or flowline connection body) relative to the tubing hanger while landing the tree on the wellhead are provided. This alignment is accomplished without the use of either a tubing spool or a BOP stack with an orientation pin. The tubing hanger alignment devices may be used to orientate the tree as the tree is landed so that the couplings and stabs between the tree and the tubing hanger line up with each other just at the moment of landing.

Document US 2021/0340831 A1 relates to systems and methods for landing a tubing hanger in a wellhead, landing a tree on the wellhead, and making electrical and hydraulic couplings between the tree and the tubing hanger without having to orient the tree or the tubing hanger relative to each other. This is accomplished using a seal sub that is coupled to the tree and lowered with the tree into contact with the tubing hanger located in the wellhead. The seal sub features an electrical conductor that facilitates electrical coupling of the tree to the tubing hanger. The tubing hanger and seal sub may include a metal-to-metal and elastomeric seal arrangement designed to seal off electrical and hydraulic connections between these components when, the tree is positioned within the wellhead.

Document “VXTe Deepwater Tree Development - Cost and Risk Reduction Through Newand Advanced Technology”, by A. B. Mitchell et al., Dril- Quip Inc, published on the 4^th May 2020 as part of the Offshore Technology Conference, Houston, TX, USA, 4-7 May 2020 relates to a VXTe system featuring several pieces of technology that work together to eliminate a tubing head. Tubing hanger alignment is solved with a stab sub design, and stack-up tolerances of a landing shoulder are addressed by an automatic space out mechanism. A compact, metal sealing gate valve packaged in the tubing hanger provides the annulus control previously configured on the tubing head.

Within this context, there is still a need for an improved method for installing a tubing hanger and tree on a wellhead of a subsea oil or gas production well, in an efficient and rapid manner.

Summary of the invention

It is therefore the object of this invention to provide a method for installing a subsea tubing hanger and vertical tree on a wellhead of a subsea oil or gas production well or a subsea injection well, the method comprising:

- landing the tubing hanger in a wellhead,

- determining the orientation of the tubing hanger relative to a an alignment feature located on a housing on the wellhead,

- using the determination of the orientation of the tubing hanger relative to the alignment feature to manufacture a customized vertical tree (VXT) alignment sleeve,

- fitting the alignment sleeve on a lower end of the tree, and - installing the tree on the tubing hanger; wherein the alignment sleeve provides hydraulic, electrical and/or optical connections between the tree and the tubing hanger.

In some variations, the method comprises installing a reference unit on the wellhead, wherein the determination of the orientation of the tubing hanger relative to the alignment feature comprises taking measurements of the orientation of the tubing hanger relative to the reference unit.

In some variations, the reference unit is a production guide base (PGB) and the determination of the orientation of the tubing hanger relative to the alignment feature further comprises checking and if necessary adjusting the orientation of a heading of the PGB relative to the alignment feature.

In some variations, the reference unit is a reference jig and the determination of the orientation of the tubing hanger relative to the alignment feature further comprises taking measurements of the orientation of the reference jig relative to the alignment feature.

In some variations, the method comprises, after taking measurements of the orientation of the tubing hanger relative to the reference jig:

- removing the reference jig, and

- installing a PGB before the installing of the tree.

In some variations, the method comprises, before taking the measurements of the reference jig relative to the alignment feature, rotationally locking the reference jig to the housing using a jig alignment feature.

In some variations, the taking of measurements of the orientation of the tubing hanger relative to the reference unit comprises using a remotely operated underwater vehicle (ROV) to deploy an orientation check tool to the reference unit and tubing hanger and using the ROV to obtain the measurements.

In some variations, the orientation check tool is a laser tool that fires a laser at a reference target point located on the reference unit.

In some variations, the method comprises BOP (Blowout Preventer) removal before deploying the orientation check tool.

In some variations, the housing is a Low Pressure Wellhead Housing or a Conductor Housing.

In some variations, manufacturing the alignment sleeve comprises forming one or more conduits within the alignment sleeve.

In some variations, the alignment sleeve comprises forming a first interface located at one end of the alignment sleeve for connection with the tree, and a second interface at the other end of the alignment sleeve for connection with the tubing hanger, the first interface comprising a plurality of first ports and the second interface comprising a plurality of second ports, with each of the one or more conduits connecting a port of the second interface with a corresponding respective port of the first interface.

In some variations, each port of the plurality of second ports is angularly offset relative to the corresponding respective port of the plurality of first ports.

In some variations, the one or more conduits have a helical or partially helical shape.

In some variations, the one or more conduits comprise angularly connected segments.

In some variations, the first interface and the lower end of tree comprise respective sleeve-tree alignment features for alignment with the lower end of the tree.

In some variations, at least one of the conduits connecting a port of the first interface with a respective port of the second interface is an electrical conduit, the port of the first interface being an electrical dry/splash mate connection and the respective port of the second interface being an electrical wet mate connection.

In some variations, at least one of the conduits connecting a port of the first interface with a respective port of the second interface is a hydraulic conduit, the port of the first interface being a hydraulic dry mate connection and the respective port of the second interface being a hydraulic wet mate connection.

In some variations, at least one of the conduits connecting a port of the first interface with a respective port of the second interface is an optical conduit, the port of the first interface being an optical dry mate connection and the respective port of the second interface being an optical wet mate connection.

In some variations, at least one of the conduits connecting a port of the first interface with a respective port of the second interface is an annulus stab conduit, the port of the first interface being an annulus stab connection and the respective port of the second interface also being an annulus stab connection.

In some variations, manufacturing the alignment sleeve comprises constructing the one or more conduits along the alignment sleeve, preferably by milling.

In some variations, the manufacturing comprises capping the one or more conduits after the constructing, preferably by additive manufacturing.

In some variations, the manufacturing comprises constructing the alignment sleeve partially by additive manufacturing.

In some variations, the manufacturing comprises constructing the alignment sleeve entirely by additive manufacturing. In some variations, the method comprises constructing the one or more conduits on an exterior surface of the alignment sleeve.

In some variations, the method comprises constructing the one or more conduits within a wall of the alignment sleeve.

In some variations, manufacturing at least one of the one or more conduits comprises induction bending, forming, additive manufacturing and/or cold bending.

In some variations, the alignment sleeve has a central through hole and is fitted around a concentric production stab of the tree.

In some variations, the method comprises fitting and testing the alignment sleeve on a tree test stump.

In some variations, the installing of the tree on the tubing hanger takes place on a wire or drill pipe.

In some variations, installing the tree on the tubing hanger comprises orienting the tree to be in line with a PGB heading.

In some variations, the alignment sleeve and tubing hanger comprise other respective sleeve-tubing hanger alignment features for installing the tree on the tubing hanger.

The invention further relates to an alignment sleeve comprising a first interface for connection with a lower end of a tree, the first interface comprising a plurality of first ports, a second interface for connection with a tubing hanger installed on a wellhead, the second interface comprising a plurality of second ports, and a plurality of conduits, each of them connecting a port of the first interface with a respective corresponding port of the second interface, wherein each port of the first interface is angularly offset relative to the corresponding port of the second interface.

In some variations, the first interface comprises a sleeve-tree alignment feature for mating with a corresponding sleeve-tree alignment feature on the lower end of tree, for alignment with the lower end of the tree.

In some variations, at least one conduit connecting a port of the first interface with a respective port of the second interface is an electrical conduit, the port of the first interface being an electrical dry/splash mate connection and the respective port of the second interface being an electrical or optical wet mate connection. In some variations, at least conduit connecting a port of the first interface with a respective port of the second interface is a hydraulic conduit, the port of the first interface being a hydraulic dry mate connection and the respective port of the second interface being a hydraulic wet mate connection.

In some variations, at least one conduit connecting a port of the first interface with a respective port of the second interface is an optical conduit, the port of the first interface being an optical dry mate connection and the respective port of the second interface being an optical wet mate connection.

In some variations, at least one conduit connecting a port of the first interface with a respective port of the second interface is an annulus stab conduit, the port of the first interface being an annulus stab connection and the respective port of the second interface also being an annulus stab connection.

In some variations, the one or more conduits are on an exterior surface of the alignment sleeve.

In some variations, the one or more conduits are within a wall of the alignment sleeve.

In some variations, the alignment sleeve comprises a central through hole for fitting around a concentric production stab connected to the tree.

In some variations, the alignment sleeve comprises a sleeve-tubing hanger alignment feature for mating with a corresponding sleeve-tubing hanger alignment feature on the tubing hanger, for installing the tree on the tubing hanger.

The invention also relates to an assembly for installing a tubing hanger and tree on a wellhead of a subsea oil or gas production well or a subsea injection well, the assembly comprising:

- the alignment sleeve as described above;

- a tree; wherein the alignment sleeve is installed on a lower end of the tree.

In some variations, the alignment sleeve is fitted around a production stab extending from the lower end of the tree.

The invention also relates to a subsea wellhead installation for a subsea oil or gas production well or a subsea injection well comprising:

- a tubing hanger installed in a wellhead of the subsea oil and gas production well or the subsea injection well;

- the assembly as described above, wherein the assembly is fixed to the tubing hanger.

The present invention makes it possible to address the need mentioned above. In particular, the method provides a customized vertical Tree Alignment Sleeve which is specifically fabricated and adapted to a tree orientation to suit a Tubing Hanger which has been installed in the wellhead. The sleeve allows for an installing of the Tubing Hanger in the wellhead without orientation control (i.e. without controlling the Tubing Hanger orientation or heading). This is achieved by landing the tubing hanger in the wellhead, determining the orientation of the tubing hanger relative to an alignment feature located on a housing on the wellhead, using this determination to manufacture the customized vertical tree alignment sleeve. As a result, all the above mentioned orientation steps, such as alignment of the BOP to the PGB, use of a BOP pin and THOJ to align the tubing hanger, can be removed from the installation process, reducing the overall amount of time taken to prepare the drilling rig for Tubing Hanger installation. Specifically, landing the tubing hanger into the wellhead, i.e. without having a specific predetermined Tubing Hanger orientation, also referred to as “freely” landing the tubing hanger, provides a more straightforward and rapid installment time than when controlled orientation is required. This in turn simplifies the landing string, as the THOJ can be removed from the landing string design. Further, determining the orientation of the tubing hanger relative to the alignment feature and using this determination to manufacture a customized alignment sleeve removes the need for an early rig contract allowing the designing of any rig-specific equipment. This also removes the need to survey and modify the BOP to install an alignment system, simplifies the PGB design and also removes any need for having rig-specific subsea production system tooling i.e. THOJ, BOP Pin, Alignment Funnel. This therefore also provides for a much faster and resource-efficient installment process. By providing a customized alignment sleeve, the method can be suited to a diverse range of orientation criteria. Further, the method has no need for an orientationless interface of the tree with the tubing hanger. Rather, the method provides for an interface specific to the tubing hanger in question, which as a result allows for a method that is more accurate and more precise. The method can also allow for implementation of simplified subsea system components, for example, only a standard well and tubing hanger for the drilling and completion of the well. These steps may additionally allow for removal of a Lead Impression Tool (LIT) trip for performing a preloading of the tubing hanger in the wellhead so as to prevent rotation and vertical movement of the tubing string.

In addition, the alignment sleeve provides hydraulic, optical and/or electrical connections between the wellhead and the tree. Determining the orientation of the tubing hanger relative to the alignment feature facilitates determining the exact positioning of the tubing hanger connections, which in turn enables the connections in the alignment sleeve to directly match the orientation of the tubing hanger while at the same time matching the wellhead/alignment feature heading.

Advantageously and according to some embodiments, manufacturing the alignment sleeve comprises constructing one or more conduits within and/or exterior to the alignment sleeve. The determination of the orientation of the tubing hanger relative to the alignment feature can enable the formation of these conduits. The conduits may provide communication between corresponding conduits in the tubing hanger and corresponding conduits in the tree. The method may comprise providing the conduits in such a manner so as to join tubing hanger connections to tree-side connections, regardless of the orientation of the tubing hanger in the wellhead.

Brief description of the drawings

Non-limiting examples will now be described in reference to the accompanying drawings, where:

FIG. 1 schematically shows how the various elements used in the method of the invention interact.

FIG. 2A and FIG. 2B show the step of landing the tubing hanger in the prior art versus according to an embodiment of the invention.

FIG. 3 shows an illustration of an example of the VXT Alignment Sleeve according to an embodiment.

FIG. 4 shows illustrations of examples of the alignment sleeve according to an embodiment.

FIG. 5 shows an illustration of an example of the alignment sleeve according to an embodiment.

FIG. 6 shows illustrations of examples of the examples of the alignment sleeves of FIG. 4.

FIG. 7 shows a perspective view of the illustrations of FIG. 6.

FIG. 8 shows a perspective view of the illustrations of FIG. 4.

FIG. 9A and FIG. 9B show illustrations of an example of the alignment sleeve according to an embodiment.

FIG. 10 shows an illustration of another example of the alignment sleeve according to an embodiment.

FIG. 11 shows an illustration of another example of the alignment sleeve according to an embodiment.

FIG. 12 is another view of the same example.

FIG. 13A shows a side view of an example of the jig according to an embodiment. FIG. 13B shows a perspective view of an example of the jig of FIG. 13A.

FIG. 14A shows a plan view of an example of the jig of FIG. 13A.

FIG. 14B shows a perspective view of an example of a conductor housing according to an embodiment.

Detailed description

The invention will now be described in detail without limitation in the following description.

The method of the present invention is for installing a subsea tubing hanger and vertical tree on a wellhead of a subsea oil or gas production well or a subsea injection well. The method is implemented by landing the tubing hanger in the wellhead without any orientation control, determining the orientation of the tubing hanger relative to an alignment feature located on a housing on the wellhead, and using this determination to manufacture a customized vertical tree (VXT) Alignment Sleeve.

A “tubing hanger” refers to a component used in the completion of oil and gas production wells. It suspends production tubing inside the wellhead. A tubing hanger 202 can be seen in FIG. 1 , comprising ports such as electric and/or hydraulic and/or optical ports 210, an annulus stab port 214. The tubing hanger may also comprise an alignment key or key slot and/or a production stab connection. The tubing hanger may comprise mating bores (for example, Production and Annulus mating bores) and/or wet mate connections (for example, Hydraulic, Electrical and/or Optical wet mate connections) for mating with corresponding stabs of the tree.

The “determining" the orientation of the tubing hanger relative to an alignment feature located on a housing on the wellhead refers to a deduction or calculation of the orientation by use of at least one measurement.

A “tree" refers to a vertical subsea Christmas tree comprising a system of valves, flow paths, piping and connectors to contain and control the flow of fluid from a reservoir or from the surface by injection. An example of a perspective view of a connection end of a vertical tree 200 can be seen in FIG. 1 , comprising connections such as electric and/or hydraulic and/or optical connections 204, an annulus stab connection 208. According to the prior art, generally, each respective connection of the tubing hanger is configured for mating with each respective connection of the tree.

A “wellhead" refers to a component at the surface of an oil or gas well that provides the structural and pressure-containing interface for the drilling and production equipment. By “landing" it is meant a docking or mating of the tubing hanger in the wellhead without necessarily aligning the tubing hanger with a pre-defined heading relative to an alignment feature.

An “alignment feature located on a housing on the wellhead" is a feature located on the housing on the wellhead that acts as an ultimate reference point for the measurements of the orientation of the tubing hanger. The feature may be for example a key slot or blind slot or blind hole or OD slot on the housing. The housing may be a Wellhead Low Pressure Housing, or a conductor housing.

A “reference unit’ is a unit of a known orientation or heading relative to a subsea manifold. The reference unit may be a production guide base, or a conductor housing comprising a jig, or a Conductor Housing external alignment feature.

By taking measurements of the “orientation of the tubing hanger relative to the reference unit’, it is meant that, regardless as to the orientation or heading with which the tubing hanger is installed in the wellhead, measurements are taken so as to determine its orientation relative to that of the reference unit. These measurements are then used to determine the orientation of the tubing hanger relative to the alignment feature.

By “using the determination of the orientation of the tubing hanger relative to the alignment feature to manufacture a customized vertical tree (VXT) alignment sleeve", it is meant applying the orientation of the tubing hanger relative to the alignment feature to an alignment sleeve design so as to allow for the connections between the tubing hanger and tree to be established while ensuring the correct heading of the tree relative to the alignment feature.

A “lower end of the tree" refers to the portion of the tree that conventionally connects with the tubing hanger.

Hydraulic and/or electrical and/or optical “connections" refers to means for communication between the tubing hanger and the tree.

A “subsea injection welf’ may be a water or gas injection well.

Landing the tubing hanger in the wellhead may comprise a landing string guiding the tubing hanger down to the wellhead through the bore of a BOP which is already positioned on the wellhead, the orientation or heading of the BOP being in the direction of the orientation/heading of a production guide base or PGB. A “production guide base" or PGB relates to a structure positioned on the wellhead. This can be seen, for example, in FIG. 1 which shows an example of a PGB 120 on a wellhead 122. An ROV (Remotely Operated Underwater Vehicle) may guide the PGB to have an optimal heading or orientation (represented by the positioning of a PGB cradle 121 ) for a well jumper connection (i.e. the PGB points towards a preferred direction for jumper connection between the well and manifold) that generally provides a foundation for the orientation for the tree and an interface for connection with a Well Jumper Hub. The manifold may be on the seabed and may be connected to two or more wells via respective well jumpers. The cradle 121 can support the end of the well jumper prior to connection of the jumper to the tree.

The method may comprise, before landing the tubing hanger, landing the BOP on the wellhead without any particular orientation with respect to the PGB heading. As the tubing hanger lands in the wellhead it may lock into position to prevent vertical and rotational movement. The tubing hanger may lock into position hydraulically. Once the well is completed, the landing string and BOP may then retreat back to the drilling rig. As can been seen from FIG. 1 , the landing of the tubing hanger 202 into the wellhead 122 may comprise nestling and locking the tubing hanger 202 into the wellhead 122, the PGB 120 being positioned on and around the wellhead 122. The PGB 120 may comprise a jumper cradle 121 , the direction in which the jumper cradle 121 is pointing defining the PGB heading. The orientation of landing of the tubing hanger 202 may be irrespective of this heading, i.e. the landing may be considered to be a “free" landing. This can be seen for example, in FIG. 2A and 2B, in which FIG. 2A a. represents alignment of the tubing hanger 202 with respect to a PGB heading, that is based off the heading of the alignment feature (not shown in figure), by means of a BOP 134 comprising a BOP pin 136 and THOJ (not shown) according to the prior art, while FIG. 2B a. demonstrates that, according to the invention, the tubing hanger 202 lands without the guidance of such devices, the tubing hanger 202 having a random orientation that, in this case, is different to that of the PGB (i.e. it is not tied or defined by the alignment feature heading and in turn the PGB heading), as can be seen from the arrangement of the connections of FIG. 2B a. varying from the arrangement of the aligned ports of FIG. 2A a. FIG. 1 further explains such an arrangement, as it can be seen that the tree 200 may connect to the alignment sleeve 128, which may connect to the tubing hanger 202. Around the alignment sleeve, an annulus stab conduit 158i may connect the annulus stab connection 208 of the tree 200 to the annulus stab port 214 of the tubing hanger 202. Also around the alignment sleeve, electrical and/or optical and/or hydraulic stab conduits 158ii may connect the electric and/or hydraulic and/or optical connections 204 to the plurality of ports 210 located in the tubing hanger 202. At least one of the conduits or stabs can be said to be integrated internally into the alignment sleeve itself. Additionally or alternatively, at least one of the conduits or stabs can be said to be integrated externally, for example separately onto the alignment sleeve. The stabs and conduits 158i, 158ii may twist around the sleeve, for example outside the sleeve and/or through the walls of the sleeve to effectively connect connections (also referred to as ports) of the tree 200 to the tubing hanger 202.

Following landing of the tubing hanger into the wellhead, the method comprises determining the orientation of the tubing hanger relative to the alignment feature located on the wellhead. The orientation in question is a rotational orientation around the main (in principle vertical) axis of the wellhead. The method may comprise installing a reference unit on the wellhead, for example on the wellhead housing, and taking measurements of the reference unit relative to the alignment feature, as well as taking measurements of the installed tubing hanger 202 relative to the reference unit. These measurements may be measurements in degrees. The method may comprise determining measurements from degree (or similar) markings on the reference unit. The markings may serve as a heading measurement dial. The markings may be 360° granulations on the reference unit. These markings can allow for measuring the rotational position of the installed tubing hanger relative to the reference unit (and thus for determining the orientation of the tubing hanger relative to the alignment feature).

The method may implement a check using, for example an ROV, to take measurements to verify the heading of the alignment feature (also referred to as the heading of the installed conductor) located on the housing on the wellhead, for example relative to true north, using one or more gyro tools, such as for example, standard gyro tools used today for a standard PGB heading check. To facilitate the correct heading of PGB or conductor housing, blind holes on the outside of a LP housing (conductor housing) and/or PGB key positions may give an adjustment, for example of +/-5 degrees, on the PGB heading, should the heading of the installed PGB or conductor need to be adjusted to suit the subsea layout. These preliminary measurements may then be to ultimately determine the orientation of the tubing hanger relative to the alignment feature on the wellhead.

As can be seen in FIG. 13A, 13B and 14A, the reference unit may be a reference jig 190 on a conductor housing 182. The method may comprise landing the reference jig 190 on a conductor housing top face 196. In such a case, the PGB may not yet be installed on the wellhead. The method may comprise taking measurements of the orientation of the reference jig 190 relative to the alignment feature. The method may then comprise taking measurements of the orientation of the tubing hanger relative to the reference jig 190 in order to determine the orientation of the tubing hanger relative to the alignment feature. The reference jig may be a temporary jig. The method may comprise removing the reference jig and installing the PGB before installing the tree 200. The method may comprise removing the reference jig before the installation of other completion orientation components. As illustrated in the example of FIG. 14B, the conductor housing 182, comprises a jig alignment feature 194, such as for example a slot or blind hole. The reference jig may rotationally lock to the conductor housing 182 via the jig alignment feature. FIGs 13A, 13B and 14A show an example of the jig 190. The reference jig 190 may fit around the conductor housing 182. The reference jig 190 may comprise ROV docking receptacles 184a, 184b for receiving the ROV (for example in accordance with ISO 13628-8). The reference jig may comprise a bullseye plate 186. The reference jig may comprise markings 192 in the form of 360° granulations. The markings 192 may be on the top of the jig along its circumference, as seen from the plan view of FIG. 14A. The markings may vary in length so as to indicate a certain increment in degrees, for example shorter markings 192 indicating every 1 °, larger markings 192 indicating every 5°, and larger markings 192 again indicating every 10°. The reference jig 190 may comprise a total of 360 markings to represent 360°. Alternatively, the reference jig 190 may comprise a number of markings 192 less than 360 markings to represent 360°. Alternatively, the reference jig 190 may comprise a number of markings 192 greater than 360 markings to represent 360°, such as, for example markings to indicate every 0.5°, for example, depending on the diameter of the area (of the reference jig i.e. reference unit) upon which the markings are placed.

Alternatively, the reference unit may be the PGB. The PGB may comprise markings. The markings on the PGB may be the same markings as those described above in connection with the reference jig. Alternatively, the markings on the PGB may be different to the markings described in connection with the reference jig. The method may comprise taking measurements of the orientation of the PGB relative to the alignment feature. The method may then comprise taking measurements of the orientation of the tubing hanger relative to the PGB so as to determine the orientation of the tubing hanger relative to the alignment feature. In other words, the method may comprise determining the orientation of the tubing hanger relative to the PGB, relative to the alignment feature. The determination of the orientation of the tubing hanger relative to the alignment feature may further comprise checking and if necessary adjusting the orientation of a heading of the PGB relative to the alignment feature.

The taking of the orientation measurements of the tubing hanger relative to the reference unit may comprise using an ROV to deploy an orientation check tool to the reference unit and tubing hanger. The ROV may use the orientation check tool to check the heading of the installed Tubing Hanger relative to the reference unit (in the case that the reference unit is a reference jig, the ROV may attach to the docking receptacles of the jig).

The method may comprise using the ROV to obtain the measurements. The ROV may take the measurements using an ROV deployed laser, or mechanical tool, or by any method. The mechanical tool may for example be a physical pointer which spans from the top of the wellhead or tubing hanger down to the markings on the reference unit (for example, the 360° granulated markings). The ROV may record the measurements. Similarly, an ROV may be used to check the heading of the reference unit relative to the alignment feature. Additionally or alternatively, the ROV may carry out the adjusting of the orientation of a heading of the PGB relative to the alignment feature. The ROV may guide the PGB to the correct position relative to the alignment feature.

In the case of the reference unit being a jig, the measurements may be measurements of the heading of the installed Tubing Hanger relative to the alignment feature directly. In the case of the reference unit being a PGB, the measurements may be measurements of the heading of the installed Tubing Hanger relative to the PGB, and indirectly relative to the alignment feature on the housing on the wellhead. The orientation check tool may be a laser tool that fires a laser at a reference target point, i.e. a compass, located on the reference unit. The compass may be zeroed to the alignment feature. As can be seen for example in FIG. 14A, the ROV may fire a laser at a point 188 on the reference unit, in this example the reference unit being a jig, the ROV firing the laser at point 188 on the markings of the jig 190. ROV may record the point 188 hitting the markings. If the reference unit is a PGB, the target point or compass may be located on the PGB, for example in the form of markings on the PGB.

The method may comprise converting the marking measurements to values in degrees describing the orientation of the tubing hanger relative to the reference unit and/or to the alignment feature. The method may comprise sending the measurements onshore, for example to a manufacturing site. The method may comprise sending the measurements and orientation of the tubing hanger relative to the alignment feature. Alternatively, the method may comprise sending only the measurements. The method may comprise determining the orientation measurements of the tubing hanger relative to the alignment feature onshore, or at a later stage from when the measurements are taken. The transferring of the measurements can enable the manufacturer to have all sufficient information for manufacturing the Tree Alignment Sleeve and, according to some embodiments, the PGB. The measurements may be used for subsequent manufacturing of the customized Tree Alignment Sleeve. The method may comprise removing the BOP before deploying the orientation check tool. In the case of the reference unit being a reference jig positioned on the housing, the method may comprise recovering the jig from the wellhead before installing the PGB and vertical tree (VXT) on a wire from a vessel for subsequent installation on the wellhead. Using the jig and/or ROV can allow for more time for the manufacturing of the PGB. Also, the jig and/or ROV can allow for use of a standard PGB or a simplified PGB, for example, a PGB without an ROV docking platform or adjustable well jumper cradle.

As can be seen in FIG. 3 and following, the alignment sleeve 128 may have a generally tubular shape and may extend along a main (longitudinal) axis. It may comprise a first interface 142 at one axial end and a second interface at the opposite axial end, with an extending portion 150 axially extending between the two interfaces.

The first interface 142 may be in the form of a disc or any other shape suitable for fitting the first interface 142 with a connection area of the tree (underside of main valve block) 200. The first interface 142 may be flat so as to facilitate connection with the tree 200. The first interface 142 may have a transverse cross-sectional surface area greater than that of the extending portion 150 of the alignment sleeve 128 perpendicular to the main axis, i.e. the disc edges extend outwardly beyond the edges of the extending portion 150 of the alignment sleeve 128. Bolt holes 146 may be provided on the periphery of the first interface 142 for fixing the sleeve 128 to the tree 200, for example to a vertical tree main valve block.

The first interface 142 may comprise a first plurality of ports 104, for example in a substantially circular pattern. The first plurality of ports 104 may be at a distance from the extending edges of the first interface 142 and may be aligned with the extending portion 150. The first plurality of ports 104 may be adapted to mate with a plurality of corresponding ports located in the underside of the tree main valve block 200.

The first interface may further comprise one or more sleeve-tree alignment features 148 to assist connecting the sleeve to the tree. The sleeve-tree alignment features 148 may be in the form of pins for connection with corresponding holes, grooves or slots of the tree 200 or vice versa. For example, two sleeve-tree alignment features 148 may be provided and located at 180° degrees from one another, and/or for example at a predetermined distance between the ports 104 and bolt holes 146.

A central through hole 162 may be provided through the entire alignment sleeve 128 for fitting around a production stab 140 connected to the tree 200 (see for example FIG. 3). The Alignment Sleeve may retain and fix the Production Stab in position vertically.

As can be seen in FIG. 4, the second interface 156 at the other extremity of the alignment sleeve 128a, 128b, 128c, 128d (i.e. on the axial end opposite the axial end with the first interface 142) is adapted for connection with the “free landed” tubing hanger 202.

The second interface 156 may comprise a second plurality of ports 103. The second interface 156 may be in the form of a disc or any other shape suitable for fitting the second interface 156 with a connection area of the tubing hanger 202. The second interface 156 may be flat so as to facilitate connection with the tubing hanger 202. The second interface 156 may have a transverse cross- sectional surface area greater than that of the extending portion 150 of the sleeve but less than that of the first interface 142. The second interface 156 may comprise a diameter which is the same as or approximate to an inner diameter of the wellhead 122 and/or the inner diameter of the tubing hanger 202. As can be seen for example in FIG. 3 and FIG. 4, the extending portion 150 may comprise a sleeve-tubing hanger alignment feature 152, such as an alignment key, to engage the Alignment Sleeve into the Tubing Hanger before coupler (also referred to as connections, ports) engagement (i.e. engagement of the respective sleeve ports to the respective tubing hanger ports). Alternatively, the sleeve-tubing hanger alignment feature 152 may comprise castellations. Alternatively, the sleeve-tubing hanger alignment feature may be another type of alignment feature to one comprise keys or castellations. The sleeve-tubing hanger alignment feature 152 can facilitate mating of the alignment sleeve 128a, 128b, 128c, 128d with the tubing hanger 202.

Each port in the second plurality of ports 103 is adapted to establish a connection to a respective port 207 of the tubing hanger 202, for example an electrical, optical, hydraulic, and/or annulus stab port. This can also be seen in FIG. 4, where the ports 104 of the first interface 142 are shown to correspond to the positioning of a plurality of ports 205 located in the tree 200, and the ports 103 of the second interface 156 are shown to correspond to the positioning of a plurality of ports 210 located in the tubing hanger 202. Like for the first plurality of ports 104, the second plurality of ports 103 may be arranged e.g. in a circular pattern on the second interface 156, at a distance from the circumference of the second interface 156, and may be aligned with the extending portion 150.

Considering FIG. 5, (and for example, FIG. 1 ) alignment sleeve 128 may comprise one or more conduits 158 (conduits 158i and 158ii of FIG. 1 ). The alignment sleeve 128 may comprise one or more conduits 158 within the alignment sleeve 128. Additionally or alternatively, one or more conduits 158 may run external to the alignment sleeve 128. Additionally or alternatively, the one or more conduits 158, in the form of for example separate control lines or pipes, may be fixed to alignment sleeve. Conduits can be formed by milling and additive manufacture or could be separate or alternative manufacturing method The one or more conduits may run from the first interface 142 to the second interface 156. Each of the one or more conduits 158 may connect a port of the first plurality of ports 104 with a respective port of the second plurality of ports 103. At least a portion of the first plurality of ports 104 (e.g. all) may be outlet ports and at least a portion of the second plurality of ports 103 (e.g. all) may be inlet ports. At least a portion of the first plurality of ports 104 (e.g. all) may be inlet ports and at least a portion of the second plurality of ports 103 (e.g. all) may be outlet ports. Each respective port 104 of the first plurality of ports 104 may be configured to connect with a respective connection (e.g. annulus stab connection 208, electric and/or hydraulic and/or optical connections 204) of the tree 200. Each respective port

103 of the second plurality of ports 103 may be configured to connect with a respective connection (e.g. electric and/or hydraulic and/or optical ports 210, annulus stab port 214) of the tubing hanger 200.

At least one of the conduits 158 connecting a port 104 of the first interface 142 with a respective port 103 of the second interface 156 may be an electrical and/or optical conduit. The port 104 of the first interface 142 may be an optical dry mate connection or an optical splash mate connection or an electrical dry mate connection or an electrical splash mate connection (for example, port 104b of FIG. 3). The respective port 103 of the second interface 156 may be an optical/electrical wet mate connection. Additionally or alternatively, at least one of the conduits 158 connecting a port 104 of the first interface 142 with a respective port 103 of the second interface 156 may be a hydraulic conduit. The port 104 (for example, port 104a of FIG. 3) of the first interface 142 may be a hydraulic dry mate connection. The respective port 103 of the second interface 156 may be a hydraulic wet mate connection. The port 104 of the first interface may be a male connection or a female connection. The port 103 of the second interface may be a male connection or a female connection.

Additionally or alternatively, at least one of conduits 158 connecting a port

104 of the first interface 142 with a respective port 103 of the second interface 156 may be an annulus stab conduit. The port 104 of the first interface 142 may be an annulus stab connection (for example, port 104c of FIG. 3). The respective connector 103 of the second interface 156 may also be an annulus stab connection. The Annulus stab (i.e. annulus stab conduit) may provide hydraulic access to the well annulus between inner diameter of the Production Casing and outer diameter of the Production Tubing. The Annulus stab may be concentric and external to Production Stab outer diameter. Alternatively, the Annulus stab may be offset and separate to Production Stab outer diameter.

Referring again to FIG. 4, each of the plurality of second ports 103 may be angularly offset relative to the corresponding respective port of the plurality of first ports 104. For example, the port 103c may be an annulus stab connection angularly offset from the port 104c that is the corresponding annulus stab connection. The method may comprise selecting the offsets to suit the tubing hanger and tree connection pattern. For example, the plurality of ports 103 may have an offset of up to 180°, for example, the offset may be a 0°, 45°, 90° or 180° offset. The offset may be an offset in the clockwise direction (for example, conduits 158a, 158b of FIG. 6 indicate an offset in the clockwise direction), or in the counterclockwise direction (for example, conduits 158c of FIG. 6 indicate an offset in the counterclockwise direction). The offset may be any angle that suits the Tubing Hanger, i.e. it may be based off any of the above described measurements which may be taken inside the wellhead subsea. In FIG. 4, for alignment sleeve 128a, the offset is 0°. In other words, the second plurality of ports 103 may not have any offset with respect to the first plurality of ports 104 at all, or may comprise only a minimal offset. In FIG. 4, for alignment sleeve 128b, the offset is 90 in a clockwise direction. In FIG. 4, for alignment sleeve 128c, the offset is 180° in a clockwise direction. In FIG. 4, for alignment sleeve 128d, the offset is 45° in a counterclockwise direction.

Additionally or alternatively, at least two (for example each) of the plurality of second ports 103 may be uniformly offset relative to the corresponding respective port of the plurality of first ports 104. Additionally or alternatively, at least two (for example each) of the plurality of second ports 103 may be nonun iformly offset (i.e. of varied offsets) relative to the corresponding respective port of the plurality of first ports 104.

Additionally or alternatively, the method may comprise providing the offsets to facilitate interfacing a tree and tubing hanger with different respective connection patterns. For example, the alignment sleeve may comprise first ports 104 with offsets corresponding to a tree from a supplier A with one connection pattern, and second ports 103 with offsets corresponding to a tubing hanger from a supplier B with another connection pattern.

As illustrated for example in FIG.’s 1 , 5 to 7 and in FIG. 9B, the one or more conduits 158 (in the case of FIG. 1 conduits 158i, 158ii, or in the case of FIG. 6, conduits 158a, 158b, 158c) may have a helical or partially helical shape, or a mostly helical shape. FIG. 5 illustrates an example of how each port 103, 104 may comprise a straight cylindrical hole 160 extending longitudinally a predetermined distance into the material of the sleeve, connected with a conduit 158 which may have a smaller diameter or cross-section. In the illustrated embodiment, each conduit 158 has two straight longitudinal portions connecting to the larger cylindrical holes 160, and an intermediate portion which may be helical or otherwise (as described elsewhere) connecting both straight longitudinal portions. The (larger) straight cylindrical holes may be adapted for inserting male connectors belonging respectively to the tubing hanger and tree.

FIG. 6 provides an example of the shape of the conduits 158 for the different offsets presented in FIG. 4. As can be seen in FIG. 6, for the alignment sleeve 128b, corresponding to the 90° clockwise offset, the pitch of the helix of the conduits 158a may be larger than that for an offset of a larger angle, such as that of the alignment sleeve 128c with conduits 158b corresponding to a 180° offset. The alignment sleeve 128a may comprise a cover 164 surrounding the conduits 158.

Alternatively, and as illustrated in FIG. 11 and FIG. 12, the one or more conduits 158 may comprise angularly connected segments. The conduit may for example comprise a straight longitudinal segment 172a descending from a port 104 of the first interface 142, followed by a circumferential segment 180 connected at one end to the straight segment 172a, the circumferential segment 180 winding an offsetting distance around the sleeve, i.e. so as to reach a position in angular alignment with a corresponding second port 103, followed by another straight segment 172b connected to the other end of the circumferential segment 180 at one end, with the other end connecting to the corresponding port 103 of the second interface.

The conduits 158 may be positioned along an exterior surface of the wall of the extending portion 150 of the alignment sleeve 174, as illustrated, for example, in FIG.’s 12 to 14. As shown in FIG. 10, the conduits 158 may comprise a tubular form and may run along and optionally wind around the extending portion 150 of the sleeve, on the outside of the sleeve. Additionally or alternatively, the one or more conduits 158 may be formed within the tubular wall 174 of the extending portion 150 of the alignment sleeve 128. As also illustrated in FIG. 10, some or all of the conduits 158 may have the same diameter. Additionally or alternatively, some or all of the conduits 158 may have different diameters. The conduits 158 have an internal cross section that is curved, e.g. circular, or rectilinear, e.g. rectangular or square. For example, the conduits 158 of FIG. 10 are illustrated as being tubular with a circular or elliptical internal shape or cross- section 170. The conduits 158 may all have the same shape, or some of them at least may have different shapes. The conduits 158 may be for example spaced equally apart from one another.

The alignment sleeve 128 is manufactured taking into account the measurements described above. In particular, the angular offset between the ports 104 of the first interface 142 and the ports 103 of the second interface 156 is based on the measured orientation.

The manufacturing of the conduits 158 can facilitate overcoming any connection difficulties presented by any offset of the tubing hanger relative to the alignment feature. In other words, the manufacturing may comprise constructing the conduits 158 to overcome any variations of the positioning of the tubing hanger relative to the alignment feature.

Manufacturing the alignment sleeve 128 may comprise constructing the extending portion 150 of the sleeve 128 and separately manufacturing the first and second interfaces 142, 156 before adding them to the extending portion 150 of the sleeve 128. Alternatively, the manufacturing may comprise constructing the extending portion, first interface and second interface together as one component. The manufacturing may comprise manufacturing the ports. The manufacturing may vary the positioning of the ports 103 in circumferential position to suit the Alignment Sleeve engagement with the free landed Tubing Hanger.

Part or all of the alignment sleeve may be manufactured prior to the measurements. For example, the extending portion 150, the first interface 142 and second interface 156 may all be fully or partly manufactured prior to the measurements, and assembled in a certain manner based on the measurements. The conduits 158 may then be formed within the extending portion 150 or around the extending portion 150, based on the measurements.

Manufacturing the alignment sleeve 128 may comprise constructing the one or more conduits 158 along the alignment sleeve 128, preferably by milling, for example as grooves. As illustrated in FIG. 6 for alignment sleeve 128a, and in FIG. 7 and FIG. 8, the method may comprise sealing the conduits 158 from any communication other than that via each respective port 103, 104.

The constructing, for example the milling, of the conduit 158 may comprise removing material from the extending portion 150 of the alignment sleeve 128. The method may comprise constructing the conduit 158 so that it extends only a predetermined distance into the wall of the extending portion 150 of the alignment sleeve 128. The constructing may comprise ensuring that a predetermined wall thickness remains in the extending portion 150 of the alignment sleeve 128 after the constructing of the conduit 158. The manufacturing may comprise capping the one or more conduits 158 after the constructing, preferably by additive manufacturing. This may be to achieve the sealing referred to with regard to the alignment sleeve 128a of FIG. 6 and the alignment sleeve 128 of FIG. 9A.

The manufacturing may comprise constructing the alignment sleeve 128 partially by additive manufacturing. For example, the method may comprise manufacturing the extending portion 150, the first interface 142, and/or the second interface 156 by additive manufacturing, while the manufacturing of the one or more conduits 158 may be entirely or partially by another method. Alternatively, the manufacturing may comprise constructing the alignment sleeve 128 entirely by additive manufacturing. In other words, the manufacturing may comprise constructing the first interface 142, the second interface 156, the extending portion 150, the first plurality of ports 104, the second plurality of ports 103 and the conduits 158 by additive manufacturing. This approach may for example be preferable for meeting stricter time constraints, as it allows for a “one-step” process. Manufacturing at least one of the one or more conduits 158 may comprise induction bending. Additionally or alternatively, manufacturing at least one of the one or more conduits 158 may comprise cold bending. Additionally or alternatively, manufacturing at least one of the one or more conduits 158 may comprise forming. Induction bending and/or cold bending and/or forming may be preferable, for example, when the manufacturing comprises constructing the conduits with angular straight segments 172a, 172b and/or helical segments 180. The type or combination of manufacturing process for implementing the method may depend on application-specific requirements of the electrical and/or hydraulic connections, and/or other requirements of the tree 200 and/or tubing hanger 202.

The method of the invention may comprise fitting and testing the alignment sleeve 128 onto the tree. The ports of the first interface of the sleeve can therefore fit with the stabs (for example Production and Annulus Stabs, Hydraulic, Electrical and/or Optical stabs for operation of downhole functions) of the tree main valve block. The testing may comprise hydraulic testing. The testing may comprise electrical or optical testing. The testing may comprise flushing one or more of the conduits 158 and pressure testing the one or more conduits 158.

A period of time ranging from 1 to 6 months, preferably 2 to 3 months, may pass between the landing of the tubing hanger 202 into the wellhead 120 and the installing of the tree onto the tubing hanger 202. The manufactured sleeve 128 may have a total weight of less than 500 kg, making it suitable for air freighting for connection with the tree main valve block 200 if the tree 200 is not in the same location as the finished sleeve upon completion of the manufacturing. The installing of the tree 200 on the tubing hanger 202 may comprise the second plurality of ports 103 of the second interface 156 of the alignment sleeve 128 connecting with the connections 207 of the tubing hanger 202. The installing of the tree 200 on the tubing hanger may comprise aligning the Tree 200 to the Tubing Hanger 202 to ensure the stabs between the tree and Tubing Hanger 202 engage. Such an alignment of the tree may be a rough alignment to PGB, followed by a fine alignment to the Tubing Hanger. In installing the tree 200 on the tubing hanger, the method may comprise connecting the tree 200 to the wellhead high pressure housing by means of a wellhead connector or sealing connector, such as a VXT H4 connector 132 of FIG. 1 (this VXT H4 connector may for example be the same connector used for connecting the BOP to the wellhead). A comparison to the method of the prior art can be seen in FIG. 2A and FIG. 2B, in which, in FIG. 2A b., the tree 200 is shown to be placed on top of the tubing hanger 202 using ports 205 of the same orientation at the top of tree 200, (the figure displaying a plan view of the tree ports) as the connections 207 of the tubing hanger 202 in FIG. 2A a. In other words, the alignment with the cradle 121 (and hence, the heading and jumper 123) is shown to be consistent for all components. Meanwhile, in FIG. 2B b., the tree 200 is shown to connect with the tubing hanger 202 while the connections 205 starting at the top of the tree (the figure displaying a plan view of the tree ports) have a different orientation to those of the tubing hanger 202. In other words, the alignment with the cradle 121 (and hence, the heading and jumper 123) is shown as not having to be consistent for all components. It can be seen that the method may control the orientation of a subsea vertical tree onto an “un-orientated” tubing hanger installed in a subsea wellhead The installing of the tree 200 on the tubing hanger 202 may take place on a wire or drill pipe. Installing the tree 200 on the tubing hanger 202 may comprise orienting the tree 200 to be in line with a PGB heading (i.e. so as to have a correct tree heading).

Claims

1. A method for installing a subsea tubing hanger (202) and vertical tree (200) on a wellhead of a subsea oil or gas production well or a subsea injection well, the method comprising:

- landing the tubing hanger (202) in a wellhead,

- determining the orientation of the tubing hanger (202) relative to an alignment feature located on a housing on the wellhead,

- using the determination of the orientation of the tubing hanger (202) relative to the alignment feature to manufacture a customized vertical tree (VXT) alignment sleeve (128),

- fitting the alignment sleeve (128) on a lower end of the tree (200), and installing the tree (200) on the tubing hanger (202); wherein the alignment sleeve (128) provides hydraulic, electrical and/or optical connections between the tree (200) and the tubing hanger (202).

2. The method according to claim 1 , wherein the method comprises installing a reference unit on the wellhead, wherein the determination of the orientation of the tubing hanger (202) relative to the alignment feature comprises taking measurements of the orientation of the tubing hanger (202) relative to the reference unit.

3. The method according to claim 2, wherein the reference unit is a production guide base (PGB) (120) and the determination of the orientation of the tubing hanger (202) relative to the alignment feature further comprises checking and if necessary adjusting the orientation of a heading of the PGB relative to the alignment feature.

4. The method according to claim 2, wherein the reference unit is a reference jig (190) and the determination of the orientation of the tubing hanger (202) relative to the alignment feature further comprises taking measurements of the orientation of the reference jig (190) relative to the alignment feature.

5. The method according to claim 4, wherein the method comprises, after taking measurements of the orientation of the tubing hanger (202) relative to the reference jig (190):

- removing the reference jig (190), and installing a PGB (120) before the installing of the tree (200).

6. The method according to claim 4 or 5, wherein the method comprises, before taking the measurements of the reference jig (190) relative to the alignment feature, rotationally locking the reference jig (190) to the housing (182) using a jig alignment feature (194).

7. The method according to any one of claims 2 to 6, wherein the taking of measurements of the orientation of the tubing hanger (202) relative to the reference unit comprises using a remotely operated underwater vehicle (ROV) to deploy an orientation check tool to the reference unit and tubing hanger (202) and using the ROV to obtain the measurements.

8. The method according to claim 7, wherein the orientation check tool is a laser tool that fires a laser at a reference target point located on the reference unit.

9. The method according to claim 7 or 8, wherein the method comprises BOP (Blowout Preventer) removal before deploying the orientation check tool.

10. The method according any one of claims 1 to 9, wherein the housing is a Low Pressure Wellhead Housing or a Conductor Housing (182).

11. The method according to any one of claims 1 to 10, wherein manufacturing the alignment sleeve (128) comprises forming one or more conduits (158) within the alignment sleeve (128).

12. The method according to claim 11 , wherein the alignment sleeve (128) comprises forming a first interface (142) located at one end of the alignment sleeve (128) for connection with the tree (200), and a second interface (156) at the other end of the alignment sleeve (128) for connection with the tubing hanger (202), the first interface (142) comprising a plurality of first ports (104) and the second interface (156) comprising a plurality of second ports (103), with each of the one or more conduits (158) connecting a port (103) of the second interface (156) with a corresponding respective port (104) of the first interface (142).

13. The method according to claim 12, wherein each port (103) of the plurality of second ports (103) is angularly offset relative to the corresponding respective port (104) of the plurality of first ports (104).

14. The method according to any one of claims 11 to 13, wherein the one or more conduits (158) have a helical or partially helical shape.

15. The method according to any one of claims 11 to 14, wherein the one or more conduits (158) comprise angularly connected segments.

16. The method according to any one of claims 12 to 15, wherein the first interface (142) and the lower end of tree (200) comprise respective sleeve-tree alignment features (148) for alignment with the lower end of the tree (200).

17. The method according to any one of claims 12 to 16, wherein at least one of the conduits (158) connecting a port (104) of the first interface (142) with a respective port (103) of the second interface (156) is an electrical conduit, the port (104) of the first interface (142) being an electrical dry/splash mate connection and the respective port (103) of the second interface (156) being an electrical wet mate connection.

18. The method according to any one of claims 12 to 17, wherein at least one of the conduits (158) connecting a port (104) of the first interface (142) with a respective port (103) of the second interface (156) is a hydraulic conduit, the port (104) of the first interface (142) being a hydraulic dry mate connection and the respective port (103) of the second interface (156) being a hydraulic wet mate connection.

19. The method according to any one of claims 12 to 18, wherein at least one of the conduits (158) connecting a port (104) of the first interface (142) with a respective port (103) of the second interface (156) is an optical conduit, the port (104) of the first interface (142) being an optical dry mate connection and the respective port (103) of the second interface (156) being an optical wet mate connection.

20. The method according to any one of claims 12 to 19, wherein at least one of the conduits (158) connecting a port (104) of the first interface (142) with a respective port of the second interface (156) is an annulus stab conduit, the port (104) of the first interface (142) being an annulus stab connection and the respective port (103) of the second interface (156) also being an annulus stab connection.

21. The method according to any one of claims 11 to 20, wherein manufacturing the alignment sleeve (128) comprises constructing the one or more conduits (158) along the alignment sleeve (128), preferably by milling.

22. The method according to claim 11 to 21 , wherein the manufacturing comprises capping the one or more conduits (158) after the constructing, preferably by additive manufacturing.

23. The method according to any one of claims 1 to 22, wherein the manufacturing comprises constructing the alignment sleeve (128) partially by additive manufacturing.

24. The method according to any one of claims 1 to 22, wherein the manufacturing comprises constructing the alignment sleeve (128) entirely by additive manufacturing.

25. The method according to any one of claims 11 to 24, wherein the method comprises constructing the one or more conduits (158) on an exterior surface of the alignment sleeve (128).

26. The method according to any one of claims 11 to 25, wherein the method comprises constructing the one or more conduits (158) within a wall of the alignment sleeve (128). The method according to any one of claims 11 to 26, wherein manufacturing at least one of the one or more conduits (158) comprises induction bending, forming, additive manufacturing and/or cold bending. The method according or claim 1 or 27, wherein the alignment sleeve (128) has a central through hole (162) and is fitted around a concentric production stab of the tree (200). The method according to any one of claims 1 to 28, wherein the method comprises fitting and testing the alignment sleeve (128) on a tree (200) test stump. The method according to any one of claims 1 to 29, wherein the installing of the tree (200) on the tubing hanger (202) takes place on a wire or drill pipe. The method according to any one of claims 1 to 30, wherein installing the tree (200) on the tubing hanger (202) comprises orienting the tree (200) to be in line with a PGB 120 heading. The method according to any one of claims 1 to 31 , wherein the alignment sleeve (128) and tubing hanger (202) comprise other respective sleeve-tubing hanger alignment features (152) for installing the tree (200) on the tubing hanger (202). An alignment sleeve (128) comprising a first interface (142) for connection with a lower end of a tree (200), the first interface (142) comprising a plurality of first ports (104), a second interface (156) for connection with a tubing hanger (202) installed on a wellhead, the second interface (156) comprising a plurality of second ports (103), and a plurality of conduits (158), each of them connecting a port (104) of the first interface (142) with a respective corresponding port (103) of the second interface (156), wherein each port (104) of the first interface (142) is angularly offset relative to the corresponding port (103) of the second interface (156). The alignment sleeve (128) according to claim 33, wherein the one or more conduits (158) have a helical or partially helical shape. 35. The alignment sleeve (128) according to claim 33 or 34, wherein the one or more conduits (158) comprise angularly connected segments.

36. The alignment sleeve (128) according to any one of claims 33 to 36, wherein the first interface (142) comprises a sleeve-tree alignment feature for mating with a corresponding sleeve-tree alignment feature on the lower end of tree (200), for alignment with the lower end of the tree (200).

37. The alignment sleeve (128) according to any one of claims 33 to 36, wherein at least one conduit (158) connecting a port (104) of the first interface (142) with a respective port (103) of the second interface (156) is an electrical conduit, the port (104) of the first interface (142) being an electrical dry/splash mate connection and the respective port (103) of the second interface (156) being an electrical or optical wet mate connection.

38. The alignment sleeve (128) according to any one of claims 33 to 37, wherein at least conduit (158) connecting a port (104) of the first interface (142) with a respective port (103) of the second interface (156) is a hydraulic conduit, the port (104) of the first interface (142) being a hydraulic dry mate connection and the respective port (103) of the second interface (156) being a hydraulic wet mate connection.

39. The alignment sleeve (128) according to any one of claims 33 to 38, wherein at least one conduit (158) connecting a port (104) of the first interface (142) with a respective port (103) of the second interface (156) is an optical conduit, the port (104) of the first interface (142) being an optical dry mate connection and the respective port (103) of the second interface (156) being an optical wet mate connection.

40. The alignment sleeve (128) according to any one of claims 33 to 39, wherein at least one conduit (158) connecting a port (104) of the first interface (142) with a respective port (103) of the second interface (156) is an annulus stab conduit, the port (104) of the first interface (142) being an annulus stab connection and the respective port (103) of the second interface (156) also being an annulus stab connection. The alignment sleeve (128) according to any one of claims 33 to 40, wherein the one or more conduits (158) are on an exterior surface of the alignment sleeve. The alignment sleeve (128) according to any one of claims 33 to 40, wherein the one or more conduits (158) are within a wall of the alignment sleeve. The alignment sleeve (128) according to any one of claims 33 to 42, wherein the alignment sleeve comprises a central through hole for fitting around a concentric production stab connected to the tree (200). The alignment sleeve (128) according to any one of claims 33 to 43, wherein the alignment sleeve comprises a sleeve-tubing hanger alignment feature for mating with a corresponding sleeve-tubing hanger alignment feature on the tubing hanger (202), for installing the tree (200) on the tubing hanger (202). An assembly for installing a tubing hanger (202) and tree (200) on a wellhead of a subsea oil or gas production well or a subsea injection well, the assembly comprising:

- the alignment sleeve (128) according to any one of claims 33 to 45;

- a tree (200);

- wherein the alignment sleeve is installed on a lower end of the tree (200). The assembly according to claim 45, wherein the alignment sleeve (128) is fitted around a production stab extending from the lower end of the tree (200). A subsea wellhead installation for a subsea oil or gas production well or a subsea injection well comprising:

- a tubing hanger (202) installed in a wellhead of the subsea oil and gas production well or the subsea injection well; - the assembly of claim 45 or 46, wherein the assembly is fixed to the tubing hanger (202).